V. Contested Issues and Positions of Parties

A. Recovery of DWR Bond Charges

1. Background

Current bundled customers, such as DL customers who received bundled service subsequent to January 17, 2001, did not pay fully for the DWR's procurement costs incurred during 2001. In order to reduce the immediate rate impact, DWR anticipated financing a part of the costs incurred during 2001 at the highest recovery levels by issuing bonds. Under AB 1X, the revenue shortfall for the historic period was to be financed through the sale of State of California Bonds. In D.02-02-051, the Commission adopted a "Rate Agreement" governing the terms by which the Bonds would be administered. As stated in D.02-02-051:

Under the Act, the Commission has an obligation to impose charges on electric customers that are sufficient to compensate DWR for its costs under the Act, including procuring and delivering power, and paying bond principal and interest.

The adopted Rate Agreement establishes two streams of revenues. One stream of revenues will come from Bond Charges imposed on electric customers, and is designed to pay for bond-related costs. The second stream of revenues will come from Power Charges imposed on electric customers who buy power from DWR, and is designed to pay for the costs that DWR incurs to procure and deliver power. Both streams of revenue are necessary for DWR to issue bonds with investment-grade ratings.

In D.02-11-022, we directed that a Bond Charge be imposed on DA customers (other than those that have remained continuously on DA service) on a cents/kilowatts-hour (kWh) basis equivalent to that imposed on bundled customers. The actual determination of the revenue requirement and per-customer bond charge, however, was to be implemented in A.00-11-038 et al. (the "Bond Charge" phase).¹⁵ On October 24, 2002, D. 02-10-063 was issued, adopting a methodology for developing a DWR Bond Charge.

D.02-10-063 was amended on rehearing by D.02-11-074. As explained in that order, DWR was to file by November 8, 2002, its more precise 2003 bond revenue requirement for bond-related costs with the Energy Division once the bonds have been placed and DWR has determined its actual bond-related charges. The utilities were then required to make compliance advice letter filings within five days following DWR's updated submission to impose a per kWh hour Bond charge on non-exempt bundled consumption delivered on and after November 15, 2002. SDGE, SCE, and PG&E were to calculate a uniform per kWh charge by dividing the more precise 2003 bond revenue requirement by 106,222 GWh.¹⁶

The determination of whether, or to what extent, Customer Generation load should pay for bond-related costs was deferred to this phase. Pending the implementation of any actual bond charge recovery, we made provision in D.02-10-063 for the tracking of both DA and DL cost responsibility, and ordered each of the utilities to create a Bond-Charge Balancing Account (BCBA) for that purpose.

Once this instant decision becomes final and unappealable, the actual Bond Charge component of the CRS will be implemented for Customer Generation load, on the terms as set forth in this order, as discussed below.

2. Parties' Positions Prior to the Settlement

Prior to the settlement, two opposing views generally emerged concerning applicability of the Bond Charge. Parties representing utility and bundled customer interests (i.e., ORA and TURN) contended that DL should pay all charges related to the DWR bonds on the same basis as bundled customers.¹⁷ Other parties proposed alternatives to a one-size-fits-all bond charge.¹⁸

Parties representing Customer Generation interests advocated an opposing view. A number of parties claimed the Commission lacks authority to impose any charge related to the DWR bonds on DL.¹⁹ Parties also argued that imposing Bond Charges would run counter to various state and federal mandates to encourage the development of preferred forms of alternative generation, and that there should be exemptions from DWR's past costs for small clean distributed generation,²⁰ for distributed solar generation,²¹ and for certain other types of customer generation.²²

3. Proposed Settlement Treatment

In Sections 5.3.1 and 5.3.2, the Settlement Agreement proposes to assess a DWR "Shortfall Charge" in lieu of a Bond Charge. The "Shortfall Charge" would apply only to customers that departed the utility to receive service from Customer Generation after January 17, 2001. The "Shortfall Charge" equals 72% of the Bond Charge that will be assessed on bundled customers in A.00-11-038 et al. This percentage level is premised on holding Customer Generation responsible only for the DWR historical shortfall incurred during 2001 and a proportionate share of costs related in general to issuance bonds to amortize this shortfall.

The 72% factor is based on a ratio of (1) a hypothetical bond issuance of $8.6 billion and (2) the approximate actual bond issuance, estimated at about $11.95 billion, as derived by a DWR in a data response contained in Exhibit 3 of the Bond Charge proceedings in A.00-11-038 et al. The derivation of the $8.6 billion hypothetical shortfall is set forth in Appendix C to the Settlement Agreement. As explained in DWR's Response to Data Request No. 3:

"A hypothetical ... bond issue [of $8.6 billion]... would generate sufficient bond proceeds to: finance the Department's undercollections through September 20, 2001; finance the carrying costs of the undercollections from the date of cost incurrence through a hypothetical bond closing date of October 10, 2002; fund bond-related accounts at levels required to comply with the Bond Indenture; fund credit enhancement and issuance costs associated with the bonds. The sizing of the bond issue does not reflect any financing of any of the Department's power purchasing program reserves."²³

DL customers, by paying the DWR Shortfall Charge provided in the Settlement Agreement, would contribute only to DWR's recovery of its Historical Shortfall and related administrative, financing and carrying costs, but not to the funding of reserve accounts that could be used for DWR forward costs and later reductions to bundled customer Bond Charges.²⁴

Section 5.3.2.1 calls for Customer Generation load to pay a full 20-year bond charge at the 72% ratio although bundled customers are expected to pay a reduced bond charge for the last few years of the amortization due to the use of operating reserves to reduce power charges or to pay down the bonds. Bundled and DA customers pre-fund deposit and reserve accounts associated with the DWR bond issue and receive the benefits of these funds over the life of the bonds. Customer Generation DL would neither pre-fund the deposit and reserve accounts associated with the bond issue nor receive the benefits of these funds during the life of the bonds.

4. Parties' Positions in Opposition to the Settlement

SDG&E and ORA oppose the Shortfall Charge, arguing that Departing Load should bear the same DWR Bond Charge as bundled customers. SDG&E and ORA argue that the Settlement's proposed approach contradicts the treatment applied to DA customers, as adopted in D.02-11-022 which reflected 100% of the Bond Charge revenue requirement. In view of the Commission's rejection of a partial bond charge for DA customers, ORA and SDG&E argue that the Agreement should be amended to make it consistent with the treatment of the DA. If the Agreement were altered to apply a uniform Bond Charge equivalent that applied to direct access customers, then the whole calculation and qualification sections of Section 5.3 would become superfluous (with the exception of 5.3.3 which allows a lump sum payment of the bond charge).

Settling Parties defend the 72% Shortfall Charge, arguing that it merely represents an alternative rate design. Although the Commission rejected "double-counting" arguments in D.02-11-022, Settling Parties argue that they have used a different rationale to justify their proposal. DL parties do not claim that a full Bond Charge constitutes double-counting, but instead, maintain that the DWR Bond Charge "impermissibly co-mingled" past and forward costs. DL parties contend that to the extent that forward costs are not recoverable from DL customers, such customers that depart the grid will not receive any offsetting benefit from the funding of forward costs. Therefore, if the Commission decides to apply a charge for DWR Historical Shortfall to DL, Settling Parties claim that charge should recover only costs related to the Historical Shortfall.²⁵ The Settling Parties argue that the DWR Shortfall Charge will not result in any net harm to other customers, given that DL will not receive future benefits of accounts they do not fund, and bundled service customers are assured that DL will contribute to recovery of DWR Historical Costs.²⁶

ORA and SDG&E contend that DL customers still receive a disproportionate benefit in the early years through a reduced bond charge in exchange for bundled customers bearing the risk surrounding the future risk of funds in the operating reserves. ORA and SDG&E argue that this is not fair.

On the other hand, various parties representing Customer Generation interests take the opposite position, arguing that even the Shortfall Charge is too much, and that in fact, no shortfall charge should be assessed at all, particularly for certain preferred categories of alternative generation. These arguments essentially apply both to the historic as well as the ongoing DWR charges.

B. DWR Ongoing Power Costs

1. Positions of Parties Prior to the Settlement

In their cases-in-chief, PG&E and SCE proposed that Customer Generation loads that departed from utility service after January 17, 2001, when DWR entered the procurement market on behalf of utility customers, should not be allowed to escape their fair share of DWR's ongoing power costs. PG&E argues that all customers on PG&E's system, as of January 17, 2001, benefited from DWR's role as "default provider." PG&E and SCE do not propose to apply any DWR charges to customers that departed its system prior to January 17, 2001, since such customers never benefited from DWR-procured power.

SDG&E does not propose to charge any Customer Generation load for DWR-related ongoing power charges. SDG&E does not believe that assessing such charges is warranted, arguing that DWR did not incur costs on behalf of such customers, but assumed they would procure their power independently of DWR through self-generation.

TURN proposed that Customer Generation should pay for ongoing DWR power charges, with the exception of those eligible for standby charge exemptions (net metered customers plus new Customer Generation under five MW installed before the specific dates established by legislation). TURN believes that this limited exemption would avoid double-counting of charges that are already collected in those standby charges.

ORA proposes that all Customer Generation load should bear a share of the ongoing DWR power charge. ORA recommends, for now, adoption of an identical surcharge applicable both to direct access and departing load based on Navigant's modeling of the cost-impact of last year's return of a substantial load from bundled service to direct access. Any surcharge true-up in 2003 or 2004 could then capture incremental cost impacts of departing load. ORA anticipates the three utilities will actually implement a surcharge related to departing load via existing rate schedules.²⁷

2. Position of Parties to the Settlement Agreement

The Settlement Agreement provides that DL shall pay a component for DWR ongoing power charges, subject to certain specified exclusions, equal to per-kWh cost responsibility component adopted for DA customers in this proceeding to recover DWR purchases. The DWR ongoing power charge component would apply on or after January 1, 2003, provided that the charge would not apply to

· Existing load served by Customer generation that departed utility service on or before January 17, 2001;

· "Grandfathered" DL that becomes operational on or before January 1, 2003, or that submitted its CEQA application on or before August 29, 2001 and becomes operational on or before January 1, 2004;

· "Qualifying" New DL that falls within an annual megawatt cap.²⁸

The MW cap proposed in the Settlement Agreement is based on the forecast of Customer Generation that was available to DWR at the time the contracts were being negotiated. Settling Parties argue that there is therefore a logical connection between the amount of Customer Generation excluded from going-forward costs and the amount of Customer Generation for which DWR was not negotiating contracts.

3. Comments on the Settlement

Various parties filed comments in support of the Settlement Agreement's treatment of forward-looking DWR power costs. CPA endorses the Settlement Agreement's exemption for new, qualifying distributed generation, up to the proposed annual caps as being consistent with DWR's planning assumptions in contracting for long-term power resources, and also meeting the Authority Board of Director's policy goal to seek exemption from surcharges for a minimum of 200 MW of clean Distributed Generation per year.²⁹ CMTA likewise agrees with this approach and believes that such a cap reflects the fact that DWR assembled its portfolio of generation supplies under the assumption that customers would continue to avail themselves of self-generation.³⁰

Certain parties also opposed the Settlement's proposed treatment of DWR ongoing costs. Controversy focused primarily around the provisions relating to the proposed MW cap. ORA argues that the cap is too high, to the point that "it equals a complete exemption in fact."³¹ Others argue that the cap does not go far enough, but that additional load should be excluded from DWR power charges.

a) Position of ORA

ORA argues that the size of the cap exemption is in conflict with the public interest that Departing Load customers contribute to ongoing power purchase costs to prevent any shift of costs to bundled customers. ORA notes that the amount of this load could cumulatively total 2,958 MW of load.³² For perspective, ORA states that this total is almost equivalent to SDG&E's current peak load forecast (3,255 MW) and represents 25% of the current capacity under long term power contracts by DWR. ORA believes that the cap emaciates Section 6.1 of the Settlement which states, "Departing Load shall pay its share of CDWR Forward Costs as provided in this Section." (Settlement Agreement, p. 8.) The Summary of the Agreement at Section 2.2.3 states in part:

"The megawatt cap reflects the amount of reduction for Customer Generation in the forecast relied upon by the CDWR in negotiating forward purchase obligations." (Settlement Agreement, p. 2.)

ORA argues, however, that there is no proof to support Section 2.2.3, directly linking the forecast of electric load made by Navigant to the actual contracting and purchasing decisions of DWR on behalf of utility customers, but only vague assertions and general statements made by some parties. ORA believes that any attempt to adjust the DA surcharge to account for a forecast of departing load would be highly speculative, resulting in new levels of complexity, and involving more computer runs by DWR.

ORA argues that although Navigant "assumed" the IOU forecasts included Customer Generation,³³ DWR Witness McDonald "never saw any explicit assumptions [from PG&E or SDG&E].³⁴" Witness Keane testified that PG&E didn't provide any forecasts to DWR until June of 2001.³⁵ ([T]his [forecast] was given to DWR after most of its contracts had already been entered into.³⁶

ORA argues that, even assuming that the Navigant forecasts estimated DG forecasts, there is no evidence that DWR used the Navigant forecasts to determine procurement needs. Navigant witness McDonald stated, "Our job was generally to give [the contracting teams] the facts and not to make recommendations in terms of how much they should be buying or the specifics of the contracts.³⁷" ORA contends that while DWR may have known Navigant's "net result" but "they did not know even how much of it was conservation versus distributed generation." (Id. at 1475:15-17 and 1483:21-24.)

ORA believes that while the net short forecasts provided by Navigant served perhaps as a "guide," they did not determine how much power DWR ultimately would be forced to contractually purchase. ORA argues that exemption of a substantial amount of utility load from any on-going cost responsibility of the DWR contracts should not be based on such a tenuous link between the forecast of net short requirements and the actual contract outcomes, particularly given DWR's weak bargaining position in what was a sellers' market.

ORA offers its own alternative proposed MW caps on DL exemptions from DWR ongoing power charges, as set forth in Appendix A of ORA's comments on the Settlement Agreement. ORA's alternative caps represent a significant reduction in DL exemptions compared with the Settlement Agreement.

b) Position of Parties Representing Customer Generation Interests

Other parties oppose the cap proposed in the Settlement Agreement, arguing that it doesn't exempt enough load, and seek to extend exemptions from the DWR forward charges even further. These parties advocate exemption from cost responsibility charges based on the alleged adverse economic impacts that would discourage development of Customer Generation.³⁸ These parties argue that many Customer Generation projects would be uneconomical if the Settlement Agreement were adopted, and would thereby inhibit the Customer Generation industry. CLECA argues that impairment of incentives for Customer generation would adversely impact all electric customers in California by diminishing perhaps the best opportunity to add new generation resources and thereby avoid another power supply shortage.

A number of parties argue that the cap is unfair to smaller generators, and seek various exemptions from the cap based on public policy considerations.³⁹ AReM/WPTF, for example, recommends that new small cogeneration projects with a nameplate rating of five MW or less be exempt from the annual MW cap. AReM/WPTF express concern that the annual MW cap could be "eaten up" by a few large cogeneration projects and recommends that new small cogeneration projects with a nameplate rating of five MW or less be excluded from the annual megawatt cap.⁴⁰ This concern is heightened by the provision of the Settlement Agreement that sets aside ten percent of the annual cap for one specific customer.⁴¹

The CPA recommends that all small DG projects of one MW or less in size should be exempt from the need to qualify under the annual MW cap on departing load exempted from CRS for CDWR's ongoing costs, and, instead, should be automatically exempt from such charges.⁴²

CPA also recommends that zero, near-zero and low-emission (ultra-clean) DG technologies be exempt from paying tail CTC and costs in SCE's PROACT.⁴³ Similarly, the South Coast Air Quality Management District (District) seeks exemption for small, ultra-clean DG of five MW or less in size from all cost responsibility surcharges.⁴⁴ The Center for Energy Efficiency and Renewable Technologies (CEERT) also calls for the exemption of ultra-clean DG without regard to the MW cap,⁴⁵ as does Capstone Turbine Corporation (Capstone).⁴⁶

Public Utilities Code Section 353.2(a) defines "ultra-clean and low-emission distributed generation" as any electric generation technology that commences its initial operation between January 1, 2003, and December 31, 2005, and:

"produces zero emissions during its operation or produces emissions during its operation that are equal to or less than the 2007 State Air Resources Board emission limits for distributed generation, except that technologies operating by combustion must operate in a combined heat and power application with a 60-percent system efficiency on a higher heating value."

Section 353.2(b) also states: "In establishing rates and fees, the [C]ommission may consider energy efficiency and emission performance to encourage early compliance with air quality standards established by the State Air Resources Board for ultra-clean and low-emission distributed generation."

CEERT argues that imposing CRS on emerging, ultra-clean distributed generation will impair the ability of these technologies to compete against dirtier, gas-fired forms of distributed generation, such as single-cycle microturbines and diesel generators.⁴⁷ CEERT claims that it would be contrary to legislative intent and state policy to apply excessive charges to this type of DG. CEERT argues that the Settlement Agreement will inappropriately penalize customers for choosing to operate zero, near-zero and low-emission DG.

CEERT proposes a three-tiered approach to encourage use of and achieve the greatest environmental benefit from this electric generation technology: (1) a minimum of several hundred new MW of zero, near zero and low-emission distributed generation technologies should be brought on-line by 2005 (2) discounted fees should be applied to these technologies based on performance; and (3) net metered solar and biogas installations should be exempted from CRS entirely, primarily due to practical difficulties in implementation.

CEERT expresses concern that the CARB may be pressured to roll back recently adopted DG emissions standards unless a minimum of several hundred MWs of DG, which meet the 2007 standards, are installed by 2005.⁴⁸ CEERT, therefore, recommends that the Commission act to encourage the addition of as much on-line capacity of this type of DG by 2005. The structure for implementing this goal should include first-in-line priority to entering the system over other dirtier types of technologies, exempting these clean technologies from any potential future cap(s) on DG, and possibly also targeting MW goals and an annual ramp-up schedule.

The CalSEIA recommends a blanket exemption for DL served by distributed solar generation.⁴⁹ CalSEIA opposes any surcharges on customers investing in solar generation facilities beyond otherwise applicable rates for net power drawn from the grid.⁵⁰ CalSEIA argues that imposition of surcharges beyond those provided for in otherwise applicable tariffs for net power would erect new and potentially very significant barriers to further development of clean, renewable generation, and would be inconsistent with numerous policies and programs established by the Legislature, the CEC, and the Commission.

c) Position of SDG&E and ORA

ORA opposes granting any exemptions from cost responsibility surcharges for Customer Generation based on claims that incentives should be provided to promote growth of renewable and low emission customer generation technologies. SDG&E opposes recognizing any such exemptions with respect to the DWR Bond Charge, but favors recognizing such exemptions with respect to forward-looking DWR power charges.

A. SCE'S Historical Procurement Charge

1. Parties' Positions - Pre-Settlement

In its opening testimony in this phase of the proceeding, SCE proposed to apply the HPC to DL customers on the same basis as was adopted for DA customers in D.02-07-032. The HPC provided for recovery of the costs in SCE's PROACT. Because DL customers affected by SCE's HPC proposal did not receive adequate notice, SCE agreed to withdraw its testimony in the A.98-07-003 proceeding proposing application of the HPC to DL customers. The HPC adopted in D.02-07-032 thus only applies to DA customers.

SCE argues that because the scope of this proceeding has been expanded to include recovery of costs from DL customers, it should be allowed to renew its proposal for application of the HPC to DL customers.

Real Energy and the Joint Parties argue that affected DL parties still have had no opportunity to comment or to provide input regarding SCE's HPC because DL issues were specifically excluded from the A.98-07-003 proceeding where the HPC was litigated and adopted. These parties contend that SCE has offered no evidence as to what, if any, of these costs may have been incurred by DL customers. If the Commission chooses to impose an SCE HPC on DL customers, however, the parties argue that such charge should only be considered for DL customers that leave the utility system after a final decision is issued in this proceeding. Moreover, the parties argue that no HPC should be imposed against such DL customers absent a showing that some portion of the PROACT balance is attributable to them.

CLECA acknowledges that "departing load customers should pay for their share of these costs by both their serving utility and the DWR" and therefore agrees that "the HPC may be appropriate."⁵¹ CPA maintains that new qualifying Customer Generation falling within the annual MW caps should also possibly be exempt from SCE and PG&E's historic charges, citing the "state's expressed need to increase energy supply resources in California and the Commission's recognition of "distributed generation as a desired new resource."⁵² Similarly, Capstone argues that small clean distributed generation should be exempted from utility historical costs based on the "offsetting benefits" of such generation.⁵³

2. Proposed Settlement Treatment

The Settlement Agreement proposes that DL customers pay a share of SCE's HPC as prescribed in Section 7.1, based on a customer-specific analysis of the customer's contribution to the utility shortfall and the revenues that customer has already contributed toward recovery of those costs. The customer-specific analysis is based on the methodology specified in Appendix B of the Settlement Agreement. The calculation will compare the generation revenue received since May 2000 with costs incurred to serve the customer's documented consumption. The customer's cost responsibility will be determined by multiplying the customer's cumulative undercollection as of August 31, 2002, by the ratio of the starting balance of the costs in SCE's PROACT. The HPC to be assessed upon a customer's departure will equal the difference between the customer-specific HPC obligation at the start of the recovery period and the customer's total contributions to PROACT. This obligation will be corrected by the projected ratio of load to be served by Customer Generation to the pre-departure load.

B. Ongoing Transition Costs

1. Background

At issue are also the recovery of certain utility-related above-market costs assignable to DL served by Customer Generation. These costs relate to what are commonly called "tail" competition transition charges (CTC). CTC was originally envisioned as a byproduct of a industry restructuring program to provide for a competitive environment pursuant to legislative enacted in AB 1890. As originally envisioned, AB 1890 was to provide for an "orderly" transition to a competitive generation market which would be completed by March 2002. (§ 330.)

Public Utilities Code Section 369 provides that "[t]he commission shall establish an effective mechanism that ensures recovery of transition costs referred to in Sections 367, 368, 375, 376, and subject to the conditions in Sections 371 and 374, inclusive, from all existing and future consumers in the [utility's] service territory ... ." Section 368(a) prescribes that electric rates would remain fixed at the June 10, 1996 levels, through March 31, 2002 at the latest except for residential and small commercial customer rates which were reduced by 10%. These frozen rates, along with a residual component of rates specifically delineated as the CTC, provided an opportunity for the utilities to accrue the revenues to collect "transition costs."

D.00-06-034 in A.99-01-016 adopted a methodology for allocating ongoing transition costs after the end of the AB 1890 rate freeze, but did not address how such amounts were to be calculated. The decision directed PG&E to implement CTC through its Phase 2 general rate case (A.99-03-014) and SCE through A.00-01-009. Since these two proceedings have been suspended or otherwise terminated, the determination of an ongoing "tail" CTC applicable to DL customers remains to be addressed in this proceeding.

2. Parties' Positions - Pre-Settlement

Certain parties opposed any charge to DL customers for ongoing above-market utility portfolio costs.⁵⁴ Various parties representing Customer Generation interests argue that while AB 1890 gave the Commission limited authority to impose certain surcharges on direct access customers, it specifically exempted onsite customer generation from these charges. (§ 372 and 374.) In addition, even where AB 1890 gave the Commission authority to impose surcharges, they claim that most were subject to a statutory sunset date of December 31, 2001.

CLECA argued that "it does not make sense" that utility tail CTC should continue to apply to departing load, on the premise that "the entire concept of tail CTC has lost any meaning in the wake of the Legislature's passage of AB 6X and the return to cost-of-service ratemaking for utility generation.⁵⁵" Other parties argued in favor of similar exemptions from "tail" CTCs.⁵⁶

The utilities stated, in contrast, that some measure of ongoing utility portfolio costs must be imposed on DL.⁵⁷ PG&E proposed the continuation of the "tail CTC" under AB 1890.⁵⁸ SCE proposed that the Commission "establish a nonbypassable charge to recover the above-market costs of SCE's portfolio of retained generation and energy contracts." Unlike the "tail CTC" in AB 1890, SCE's proposed measure would have been unlimited both in term and in the resources that could be included in the ongoing charge. SCE argued that the "tail CTC," a more limited measure of ongoing utility portfolio costs, combined with a continuing cogeneration exemption, represents a reasonable compromise of positions in the interests of bundled ratepayers, the utilities and DL customers. SDG&E is uniquely situated with respect to its recovery of CTC because it has ended its rate freeze. SDG&E argued that the Commission, in this proceeding, should expressly authorize the continued collection of SDG&E's CTC pursuant to existing tariff.

3. Proposed Settlement Treatment

The Settlement Agreement proposes that all DG shall pay a provision for tail CTC, except those categories of load exempted from such a charge pursuant to any statute as of the date of execution of the Settlement Agreement. The eligible costs will be limited to those cost categories defined in Public Utilities Code Sections 367(a)(1)-(6).⁵⁹ The tail CTC would be determined as the above-market portion of the applicable CTC-related costs based on the market benchmark adopted in D.02-11-22 regarding DA CRS.

The CTC revenue requirement would be derived for the qualifying facility and power purchase agreement portfolio by multiplying the above-market per-mWh charge times forecasted consumption in the portfolio. The total tail CTC revenue requirement would constitute the above-market portion of the QF and power purchase costs, plus the employee-related transition costs and, in the case of SCE, any costs associated with the nuclear incremental cost incentive plan. The revenue requirement, divided by the total applicable load, would yield the CTC rate. The total applicable load would include bundled, direct access, and DL customers not otherwise exempted pursuant to § 372 and/or 374.

C. Miscellaneous issues

1. Definition of Customer Generation and Departing Load

In their Comments, CHW requests "clarification from the settling parties and/or the Commission that if new or incremental customer load of an existing customer is wholly or partially met through a `direct transaction' as defined by Public Utilities Code Section 331(c), and the new or incremental load does not require the use of utility transmission or distribution facilities, the load would not be treated as departing load responsible for the [DWR] bond charges."⁶⁰

The Commission has previously considered this issue in the context of CTC, for new load served by a Customer Generation unit but taking standby service from a utility. Section 369 of the Public Utilities Code states that such CTC "shall not be recoverable for new customer load or incremental load of an existing customer where the load is being met through a direct transaction and the transaction does not otherwise require the use of transmission or distribution facilities owned by the utility." In A.96-08-001 et al., the Commission considered whether taking standby service from a utility meant that the new or incremental load was "otherwise requiring" use of the utility's transmission or distribution facilities, and in D.98-12-067 the Commission implemented a "physical test" to make such a determination.⁶¹ If a Customer Generation unit serving new or incremental load can pass the physical test, the load is not considered to be departing, and is not obligated to pay CTC.

The Joint Settling Parties' intention is that this same physical test, currently embodied in the utilities' tariffs, also be used to determine whether new or incremental load is considered to be "departing" for purposes of assessing CDWR Bond and Forward charges.

Eastside argues that the definitions of Customer Generation and DL in Sections 3.11 and 3.12, respectively, are too narrow and should be expanded to include any public entity, including a Joint Power Authority. They further argue that a new Section 3.22 should be added to define the term "utility grid" to reflect their proposed modifications to Sections 3.11 and 3.12.⁶² The Joint Settling Parties oppose these proposed modifications, arguing that the definitions of "Customer Generation" and "Departing Load" were matters of much discussion and debate during settlement negotiations. The Joint Settling Parties agreed that, for the sake of clarity and ease of administration, the Settlement Agreement would conform as closely as possible to the utilities' tariff definitions of those terms. Public entities, such as Joint Power Authorities, that could potentially serve numerous customers by wheeling power from a generator over utility distribution wires, fall outside the definitions contained in the utilities' tariffs and agreed to in the Settlement Agreement. Even if particular generating arrangements currently held by public entities do not currently sell power to retail end-use customers, the potential does exist for them to do so. Applicability of fees to such arrangements would be beyond the scope of the issues addressed in this phase of this proceeding. Our intent in this decision is to focus on customer generation that is primarily used to serve on-site needs. Thus, we decline to adopt the definitional and tariff modifications requested by Eastside. In its Comments, DWR also expresses concern about the definition of "Departing Load" based on the exclusion of "new load that is served by Customer Generation and that does not rely on IOU transmission or distribution facilities."⁶³ The Joint Settling Parties indicate that they sought to conform the Settlement Agreement's definition of "Departing Load" as closely as possible to the utilities' tariff definitions. The utilities' current tariff definitions of "Departing Load" are based, in substantial part, on Public Utilities Code Section 369, as previously discussed. To the extent that so-called "islanded" Customer Generation customers are exempt from CTC, the Joint Settling Parties agree that they should also be exempt from DWR charges.

2. Biogas Digesters Exceptions to CRS

AECA supports the Settlement Agreement but is confused as to why Section 4.3 reserves the right of parties to oppose any proposal for an exemption from DWR Historical Costs and Forward Costs, or Historical Procurement Charges for eligible biogas digester customer-generators, as defined in § 2827.9.⁶⁴ According to AECA, eligible biogas digester customer-generators are exempt from departing load charges, and therefore no new or additional charges that would increase an eligible biogas digester customer-generator's charges beyond those of other customers in the same rate class may be included. Similarly, CEERT argues that the Legislature, in passing Assembly Bill No. 2228 ("AB 2228"), (Stats. 2002, ch. 845), "specifically considered and elected to exempt biogas (also known as biodigester) projects from any net metering or other charges for departing the system," and that biogas generators "should be exempted from any fees imposed by this proceeding."⁶⁵

The Joint Settling Parties agree with AECA's and CEERT's interpretation of AB 2228 and express their intention that tariffs implementing AB 2228 be filed consistent with that interpretation.

3. Implementation of Surcharges on Net Metering Customers

Both CalSEIA and CEERT argue that the Settlement Agreement fails to address the practical problems associated with imposing surcharges on net metering customers under Assembly Bill No. 58 ("AB 58"), Stats. 2002, ch. 836.⁶⁶ Section 4.3 of the Settlement was intended to reserve resolution of the issues associated with AB 58 prior to the utilities' filing of implementing tariffs. Pursuant to Section 4.3, parties reserve the right to make whatever arguments they wish regarding the applicability and implementation of DWR and utility charges to net metered customers under AB 58.

⁴⁸ Exhibit (Ex.) 116 (CEERT (Starrs)). See also, California Code of Regulations, Title 17(3)(1)(8), Article 3 (Distributed Generation Certification Program).

⁵⁹ The specific eligible cost categories covered by the CTC are: (1) employee-related transition costs through December 31, 2006; (2) power purchase contract obligations for qualifying facilities and purchase power agreements signed before December 20, 1995; (3) nuclear incremental cost incentive plan for the San Onofre Nuclear Generating Station, provided that the recovery shall not extend beyond December 31, 2003.